Heterogeneous proppant placement in a fracture with removable extrametrical material fill

ABSTRACT

A method of heterogeneous proppant placement in a subterranean fracture is disclosed. The method comprises injecting well treatment fluid including proppant ( 16 ) and proppant-spacing filler material ( 18 ) through a wellbore ( 10 ) into the fracture ( 20 ), heterogeneously placing the proppant in the fracture in a plurality of proppant clusters or islands ( 22 ) spaced apart by the material ( 24 ), and removing the filler material ( 24 ) to form open channels ( 26 ) around the pillars ( 28 ). The filler material can be dissolvable particles, initially acting as a consolidator during placement of the proppant in the fracture, and later dissolving to leave flow channels between the proppant pillars. The well treatment fluid can include extrametrical materials to provide reinforcement and consolidation of the proppant and, additionally or alternatively, to inhibit settling of the proppant in the treatment fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This non-provisional application relies on U.S. Provisional ApplicationSer. No. 61/572,354 entitled “HETEROGENEOUS PROPPANT PLACEMENT IN AFRACTURE WITH REMOVABLE EXTRAMETRICAL FILL”, filed on 15 Jul. 2011 andis hereby in its entirety incorporated by reference. The provisionalapplication is a continuation-in-part application of U.S. patentapplication Ser. No. 12/507,558, entitled “HETEROGENEOUS PROPPANTPLACEMENT IN A FRACTURE WITH REMOVABLE CHANNELANT FILL” filed on Jul.22, 2009, which is a divisional application of U.S. patent applicationSer. No. 11/608,686, now U.S. Pat. No. 7,581,590, entitled“HETEROGENEOUS PROPPANT PLACEMENT IN A FRACTURE WITH REMOVABLECHANNELANT FILL” filed on Dec. 8, 2006, which are all hereby in theirentirety incorporated by reference. This application is also acontinuation-in-part application of U.S. patent application Ser. No.12/945,426, entitled, “HETEROGENEOUS PROPPANT PLACEMENT IN A FRACTUREWITH REMOVABLE CHANNELANT FILL,” filed on Nov. 12, 2010, and acontinuation-in-part application of U.S. patent application Ser. No.12/950,180, entitled, “HETEROGENEOUS PROPPANT PLACEMENT IN A FRACTUREWITH REMOVABLE CHANNELANT FILL,” filed on Nov. 19, 2010, which are bothhereby in their entirety incorporated by reference. Further, thisapplication is also a continuation-in-part application of U.S. patentapplication Ser. No. 13/097,263, entitled, “HETEROGENEOUS PROPPANTPLACEMENT IN A FRACTURE WITH REMOVABLE CHANNELANT FILL,” filed on Apr.29, 2011.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

Various methods are known for fracturing a subterranean formation toenhance the production of fluids therefrom. In a typical application, apressurized fracturing fluid hydraulically creates and propagates afracture. The fracturing fluid carries proppant particulates into theextending fracture. When the fracturing fluid is removed, the fracturedoes not completely close from the loss of hydraulic pressure; instead,the fracture remains propped open by the packed proppant, allowingfluids to flow from the formation through the proppant pack to theproduction wellbore.

The success of the fracturing treatment is determined by the ability ofdesired fluids to flow from the formation through the proppant pack. Inother words, the proppant pack or matrix must have a high permeabilityrelative to the formation for fluid to flow to the wellbore with lowresistance. Furthermore, the surface regions of the fracture should notbe significantly damaged by the process of fracturing in order to retainfluid permeability via the surface regions for optimal flow from theformation into the fracture and the proppant pack.

Some methods have sought to increase the permeability of the proppantpack by increasing the porosity of the interstitial channels betweenadjacent proppant particles within the proppant matrix. For example,United States Patent Application Publication Number 200600408944A1 (vanBatenburg, et al.) discloses a method of forming a high porosity proppedfracture with a slurry that includes a fracturing fluid, proppantparticulates and a weighting agent. These technologies seek todistribute the porosity and interstitial flow passages as uniformly aspossible in the consolidated proppant matrix filling the fracture, andthus employ homogeneous proppant placement procedures to substantiallyuniformly distribute the proppant and non-proppant, porosity-inducingmaterials within the fracture.

In other methods, as in United States Patent Application PublicationNumber 20060048943A1 (Parker, et al.), proppant particulates anddegradable material are not segregated before, during or after injectionin order to help maintain uniformity within the proppant matrix.Fracturing fluids are thoroughly mixed to prevent any segregation ofproppant and non-proppant particulates. In another approach,non-proppant materials have a size, shape and specific gravity similarto that of the proppant to maintain substantial uniformity within themixture of particles in the fracturing fluid and within the resultingproppant pack. A tackifying compound coating on the particulates hasalso been used to enhance the homogenous distribution of proppant andnon-proppant particulates as they are blended and pumped downhole into afracture.

A recent approach to improving hydraulic fracture conductivity has beento try to construct proppant clusters in the fracture, as opposed toconstructing a continuous proppant pack. U.S. Pat. No. 6,776,235(England) discloses a method for hydraulically fracturing a subterraneanformation involving alternating stages of proppant-containing hydraulicfracturing fluids contrasting in their proppant-settling rates to formproppant clusters as posts that prevent fracture closing. This methodalternates the stages of proppant-laden and proppant-free fracturingfluids to create proppant clusters, or islands, in the fracture andchannels between them for formation fluids to flow. The amount ofproppant deposited in the fracture during each stage is modulated byvarying the fluid transport characteristics (such as viscosity andelasticity), the proppant densities, diameters, and concentrations andthe fracturing fluid injection rate. However, the positioning of theproppant-containing fluid is difficult to control. For example, theproppant-containing fluid can have a higher density than theproppant-free fluid and can thus underride the proppant-free fluid. Thisunderride can result in non-uniform distribution of proppant clusters,which in turn can lead to excessive fracture closure where there is notenough proppant and constricted flow channels where there is too muchproppant.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

According to some embodiments, a fracturing treatment includes theinjection of both proppant and a removable material that can act as fillto physically separate the proppant clusters at appropriate distancesduring placement in the fracture, but can subsequently be removed toform channels. The proppant and removable material are disposed within afracture in such a way that the removable material is segregated fromthe proppant to act as a temporary filler material compressed in thefracture in spaces between clusters or islands of proppant which formpillars to hold open the fracture. Then, the fill material is removed toform open channels for unimpeded fluid flow through the fracture in thespaces left around the proppant pillars. Applicant refers herein to theremovable extrametrical material, or channel-forming fill material as“channelant.” In alternative embodiments the extrametrical material maynot necessarily serve as a channelant.

In one aspect, embodiments are related to methods of heterogeneousproppant placement in a subterranean fracture accomplished by injectingwell treatment fluid through a wellbore into a fracture in asubterranean formation. The treatment fluid can include proppant andproppant-spacing extrametrical material. The proppant can be placed inthe fracture in a plurality of proppant clusters forming pillars spacedapart by the extrametrical material. Then, the extrametrical materialcan be removed to form open channels around the pillars for fluid flowfrom the formation through the fracture toward the wellbore.

In another aspect, embodiments are related to methods of treating asubterranean formation penetrated by a wellbore, wherein a fracture isformed within the formation by injecting a fluid into the wellbore at apressure equal to or greater than the fracture initiation pressure ofthe formation, followed by injecting one or more stages each of aproppant laded well treatment fluid and extrametrical material ladenfluid. These fluids are injected separately and/or simultaneously. Theextrametrical material may then be removed to form open channels aroundpillars of proppant for fluid flow from the formation through thefracture toward the wellbore. Removal of the extrametrical material maybe influenced by such factors as invasion of formation fluids, byexposure to water, by passage of time, by the presence of incipient ordelayed reactants in or mixed with the extrametrical material particles,by the post-injection introduction of an activating fluid, and the like,or any combination of thereof.

In an embodiment, the extrametrical material can include solid particlesthat can be consolidated between the proppant islands or pillars. In anembodiment, the proppant and extrametrical material particles can besegregated during injection of the well treatment fluid. In anotherembodiment, the extrametrical material particles can be maintained in asolid state within the fracture.

The injection can include injecting a proppant-lean carrier stage toinitiate the fracture; and thereafter injecting into the fractureproppant and extrametrical material.

In an embodiment, the injection can further include injecting a tail-instage to form a permeable proppant pack in the fracture between the openchannels and the wellbore.

In an embodiment, the treatment fluid can have mixed phases including aproppant-rich phase and an extrametrical material-rich phase. Inembodiments, the proppant-rich phase can be discontinuous. Alternativelyor additionally, the extrametrical material-rich phase can becontinuous. In another embodiment, the treatment fluid can alternatevolumes of proppant-rich fluid separated by volumes containing theextrametrical material.

The treatment fluid can alternatively or additionally include a mixtureof proppant and extrametrical material during the injection, and themethod can include the step of segregating the proppant andextrametrical material for the fracture placement. In an embodiment, thesegregation can be facilitated by density differences between theproppant and extrametrical material. Alternatively or additionally, thesegregation can be facilitated by differences between the proppant andextrametrical material.

Extrametrical material in one embodiment can include a solidacid-precursor to generate acid in the fracture. The generated acid canbe used for gel breaking in the fracturing fluid. In another embodiment,the generated acid can etch surfaces of the formation to enlarge thechannels. Alternatively or additionally, the generated acid canfacilitate consolidation of the proppant clusters.

The proppant can be sand, nut hulls, ceramics, bauxites, glass, and thelike and combinations thereof. In one embodiment, the proppant includesceramic particles having a narrow particle size distribution and sandhaving a broad particle size distribution. Resin coated proppants(various resin and plastic coatings) having a base of any of thepreviously listed propping materials such as sand, ceramics, bauxite,nut shells, etc. may be used in accordance with the embodiment. Alsoother proppants like, plastic beads such as styrene divinylbenzene, andparticulate metals may be used. Proppant used in this application maynot necessarily require the same permeability properties as typicallyrequired in conventional treatments because the overall fracturepermeability will at least partially develop from formation of channels.Other proppants may be materials such as drill cuttings that arecirculated out of the well and/or other ground minerals, as shales,mica, and the like, or even ground waste of any kind, such as slag,scoria, sinter, ash, ground plastic, crushed glass, ground metal etc.,and of which if properly consolidated, waste pillars can providesufficient strength, particularly at low closure stress, as well as anycombinations of any of the previous mentioned material types. In anembodiment, the proppant can be in the form of spheres, rods, platelets,irregular shapes and the like and combinations thereof. Many otherorganic materials could be resin coated and possible applied such aswood chips or various seeds, and the like. Essentially, the proppant canbe any material that will hold open the propped portion of the fracture.

The extrametrical material can be any material degradable or dissolvableafter placement within the fracture. The extrametrical material can be,for example, polylactic acid (PLA), polyglycolic acid (PGA), polyol,polyethylene terephthalate (PET), nylon 6, nylon 6,6, polyester,polyamide, polyolefin, polysaccharide, wax, salt, calcium carbonate,benzoic acid, naphthalene based materials, magnesium oxide, sodiumbicarbonate, soluble resins, sodium chloride, calcium chloride, ammoniumsulfate, and the like, or a combination thereof. The extrametricalmaterial can have a size and shape matching the size and shape of theproppant to promote segregation. In an embodiment, the channelant can bein the form of spheres, fibers, rods, platelets, ribbons, and the likeand combinations thereof.

In some embodiments the extrametrical materials can be, for example,glass, ceramics, carbon including carbon-based compounds, metalincluding metallic alloys, or the like, or a combination thereof, or apolymeric material such as PLA, PGA, PET, polyol, polyamide, polyimide,or the like, or a combination thereof. In an embodiment, theextrametrical materials can form of an extrametrical material-basednetwork. In an embodiment, the extrametrical materials can providereinforcement and consolidation of the proppant. In another embodiment,the extrametrical materials can inhibit differential settling ofproppant in the treatment fluid.

In yet another embodiment, the treatment fluid can include a mixture offirst and second extrametrical material types, the first extrametricalmaterial type providing reinforcement and consolidation of proppant, andthe second extrametrical material type inhibiting settling of theproppant in the treatment fluid. The first extrametrical material typecan be one of glass, ceramics, carbon and carbon-based compounds, metalsand metallic alloys, or the like or a combination thereof, and thesecond extrametrical material type can be PLA, PGA, PET, polyol,polyamide, polyimide, or the like, or a combination thereof.

Alternatively or additionally, the proppant can be self-adherent and/ornon-adherent to the extrametrical material. The proppant can have aself-adherent coating, for example. Similarly, the extrametricalmaterial of another embodiment can be self-adherent and/or non-adherentto the proppant. The extrametrical material can have a self-adherentcoating, for example.

In another embodiment, the proppant can have hydrophobic surfaces andthe extrametrical material can have hydrophilic surfaces. Alternatively,the proppant can have hydrophilic surfaces and the extrametricalmaterial hydrophobic surfaces.

In yet another aspect, method embodiments include injecting a pluralityof stages of a well treatment fluid through a wellbore into a fracturein a subterranean formation, the stages of the fluid containing at leastone of a proppant and an extrametrical material. The extrametricalmaterial comprises at least one of a solid acid-precursor to generateacid in the fracture, and a solid base-precursor to generate a base inthe fracture (in either case, a suitable acid or base is a materialwhich alters the pH of an aqueous median, in either a decreasing orincreasing direction, respectively). The proppant is placed in thefracture in a plurality of proppant clusters to form pillars. Theextrametrical material then dissolves in the fracture, which may furtherenable fluid flow from the formation through the fracture toward thewellbore (the term ‘dissolve’ in the present application means anysuitable process, either chemical or mechanical, by which theextrametrical material voids the fracture space occupied).

In yet other embodiments, methods involve injecting a plurality ofstages of a well treatment fluid through a wellbore into a fracture in asubterranean formation, where the stages of the fluid containing atleast one of a proppant and a extrametrical material, and placing theproppant in the fracture in a plurality of proppant clusters to formpillars. The extrametrical material subsequently dissolves. The zonecontacted by the treatment fluid in the formation comprises fine grainedsedimentary rock formed by consolidation of clay and silt sizedparticles into thin, relatively impermeable layers.

A further aspect involves methods where a plurality of stages of a welltreatment fluid are injected through a deviated wellbore into a fracturein a subterranean formation, and the stages of the fluid contain atleast one of a proppant and an extrametrical material. The proppant isplaced in the fracture in a plurality of proppant slugs; and the placedextrametrical material is allowed to dissolve. The treatment fluidstages are alternate volumes of proppant-rich fluid separated by volumesof extrametrical material-rich fluid.

In some embodiments, the pulsing fracturing treatment schedule iscombined with homogeneous stage at the end of the treatment. Suchapproach may provide a substantial increase in the fracture conductivityachieved by loading a heterogeneous proppant pack (combination ofproppant pillars) into the fracture.

Some embodiments are methods of reservoir stimulation with increasedfracture conductivity, achieved by heterogeneous proppant placement in ahydraulic fracture. The method provides a treatment pumping schedulewith parameters, optimized based on reservoir geomechanical properties.Design optimization can be performed either prior to the treatment or inreal time. Different embodiments of design optimization are disclosed.

Any of the methods also include the step of producing fluids such ashydrocarbons, or any other suitable fluids, from the formation throughthe open channels and the wellbore.

Some other embodiments include the use of a foamed fluid, utilizing asuitable gas, such as, but not limited to air, nitrogen, carbon dioxide,and the like, or any mixtures thereof. Any suitable ration of gas phaseto liquid phase may be utilized. In one case, the embodiment is a methodincluding injecting a first treatment fluid comprising a gas andsubstantially free of macroscopic particles through a wellbore at apressure sufficient to initiate a fracture in a subterranean formation;injecting a second treatment fluid comprising proppant and anextrametrical material through a wellbore and into a fracture in asubterranean formation, wherein the introducing is achieved with variedand pulsed proppant concentration in a pumping schedule, the pumpingschedule being optimized based on fluid and formation properties, and/orwherein the introducing is achieved by varying pumping rate duringpulses; and forming a plurality of proppant clusters comprising proppantand the extrametrical material in the fracture; where the extrametricalmaterial consolidates the proppant into clusters, and wherein theextrametrical material is degradable.

In another aspect, the method includes injecting a first treatment fluidcomprising a gas and substantially free of macroscopic particles througha wellbore at a pressure sufficient to initiate a fracture in asubterranean formation; injecting a second treatment fluid comprisingproppant and an extrametrical material through a wellbore and into afracture in a subterranean formation wherein the injecting is achievedwith varied and pulsed proppant concentration in a pumping schedule, thepumping schedule being optimized based on fluid and formationproperties, and/or wherein the introducing is achieved by varyingpumping rate during pulses; and, placing the proppant in the fracture ina plurality of proppant clusters; where the extrametrical materialreinforces the proppant clusters, and wherein the extrametrical materialis a removable material.

Yet another method includes injecting a first treatment fluid comprisinga gas and substantially free of macroscopic particles through a wellboreat a pressure sufficient to initiate a fracture in a subterraneanformation; injecting a second treatment fluid comprising proppant andfiber through a wellbore and into a fracture in a subterraneanformation; and forming a plurality of proppant clusters comprisingproppant and fiber in the fracture; where the fiber consolidates theproppant into clusters, and wherein the fiber degrades.

Another embodiment includes a method involving injecting a firsttreatment fluid comprising a gas and substantially free of macroscopicparticles through a wellbore at a pressure sufficient to initiate afracture in a subterranean formation; injecting a second treatment fluidcomprising proppant and fiber through a wellbore and into a fracture ina subterranean formation; and placing the proppant in the fracture in aplurality of proppant clusters; where the fiber reinforces the proppantclusters, and where the fiber is a removable material.

Also, another method involves constructing a system in a subterraneanformation penetrated by a wellbore, where the construction includes:

-   -   i. injecting a first treatment fluid comprising a gas and        substantially free of macroscopic particles through a wellbore        at a pressure sufficient to initiate a fracture in a        subterranean formation;    -   ii. injecting a second treatment fluid comprising proppant and        fiber through a wellbore and into the fracture, wherein the        fiber is a degradable material;    -   iii. placing the proppant in the fracture in a plurality of        proppant clusters;        then producing formation fluids from the formation, through the        system constructed.

Yet another method involves constructing a system in a subterraneanformation penetrated by a wellbore, where the construction includes:

-   -   i. injecting a first treatment fluid comprising a gas and        substantially free of macroscopic particles through a wellbore        at a pressure sufficient to initiate a fracture in a        subterranean formation;    -   ii. injecting a second treatment fluid comprising proppant and        fiber through a wellbore and into the fracture, wherein the        fiber is a removable material;    -   iii. placing the proppant in the fracture in a plurality of        proppant clusters;        then producing formation fluids from the formation, through the        system of a).

Other or alternative features will become apparent from the followingdescription, from the drawings, and from the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments will hereafter be described with reference to theaccompanying drawings, wherein like reference numerals denote likeelements. It should be understood, however, that the accompanyingdrawings illustrate only the various implementations described hereinand are not meant to limit the scope of various technologies describedherein. The drawings are as follows:

FIG. 1 schematically illustrates in section placement of proppant andremovable extrametrical material in a hydraulic fracture operationaccording to an embodiment of the disclosure;

FIG. 2 schematically illustrates in section the arrangement of thewellbore, perforations and the proppant pillars in the fracturefollowing removal of the extrametrical material from the fracture ofFIG. 1;

FIG. 3 schematically illustrates a side sectional view of a fracturefilled with segregated proppant and degradable solid acid-precursor asextrametrical material in a carbonate formation according to anembodiment of the disclosure;

FIG. 4 schematically illustrates a side sectional view of the fractureof FIG. 3 following hydrolysis of the solid acid-precursor and etchingat the faces of the fracture in the vicinity of the acid formed thereby;

FIG. 5 schematically illustrates an example of pulsation scheduleaccording to one embodiment where time is on the x-axis and proppantconcentration on the y-axis;

FIG. 6 schematically illustrates fractures filled with system of pillarsso that there are open channels remain between pillars;

FIG. 7 illustrates how channel conductivity may depend upon proppedfracture area for different ratio L/L₀;

FIG. 8 describes the results of numerical simulation for proppanttransport in a horizontal transverse fracture (with black areasrepresenting proppant) in which notations: 1—wellbore, 2—boundaries ofthe hydraulic fracture (transverse, located between stress barriers withconfined height growth), 3—proppant pulses transported radial in thecentral part of the fracture, 4—proppant pulses transported horizontallyin the wings of the fracture; and

FIG. 9 describes the schematic model representing proppant transport ina horizontal well in which notations: 1—wellbore, 2—boundaries of thehydraulic fracture (transverse, located between stress barriers withconfined height growth), 3—proppant pulses transported radial in thecentral part of the fracture, 4—proppant pulses transported horizontallyin the wings of the fracture, 5—proppant pack close to the near-wellborearea, 6—area of potential pinching, if the proppant pack notated by 5 isplaced incorrectly.

DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation—specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

The description and examples are presented solely for the purpose ofillustrating some of the various embodiments of the disclosure andshould not be construed as a limitation to the scope and applicabilityof the disclosure. While the compositions of the present disclosure aredescribed herein as comprising certain materials, it should beunderstood that the composition could optionally comprise two or morechemically different materials. In addition, the composition can alsocomprise some components other than the ones already cited. In thesummary of the disclosure and this detailed description, each numericalvalue should be read once as modified by the term “about” (unlessalready expressly so modified), and then read again as not so modifiedunless otherwise indicated in context. Also, in the summary of thedisclosure and this detailed description, it should be understood that aconcentration range listed or described as being useful, suitable, orthe like, is intended that any and every concentration within the range,including the end points, is to be considered as having been stated. Forexample, “a range of from 1 to 10” is to be read as indicating each andevery possible number along the continuum between about 1 and about 10.Thus, even if specific data points within the range, or even no datapoints within the range, are explicitly identified or refer to only afew specific, it is to be understood that inventors appreciate andunderstand that any and all data points within the range are to beconsidered to have been specified, and that inventors possession of theentire range and all points within the range.

Some embodiments utilize fluids containing a gas phase and liquid phase.As used herein, the term “liquid phase” is meant to include allcomponents of the fluid except the gas phase. The term “gas” is usedherein to describe any fluid in a gaseous state or in a supercriticalstate, wherein the gaseous state refers to any state for which thetemperature of the fluid is below its critical temperature and thepressure of the fluid is below its vapor pressure, and the supercriticalstate refers to any state for which the temperature of the fluid isabove its critical temperature. When referred to in conjunction with agas component, the terms “energized fluid”, “foam” and “fluid” may beinterchangeably used to describe any stable mixture of gas phase andliquid phase. Fluids described herein may also refer to liquids notcontaining a gas component, in accordance with the context of use.Foamed and energized fracturing fluids often contain “foamers”, mostcommonly surfactant or blends of surfactants that facilitate thedispersion of the gas into the base fluid in the form of small bubblesor droplets, and confer stability to the dispersion by retarding thecoalescence or recombination of such bubbles or droplets. Foamed andenergized fracturing fluids are generally described by their foamquality, i.e. the ratio of gas volume to the foam volume. If the foamquality is between about 52% and 95%, the fluid is conventionally calledfoam, and below about 52%, an energized fluid. However, as used hereinthe term “energized fluid” is defined as any stable mixture of gas andliquid, notwithstanding the foam quality value.

Fracturing fluids according to an example of the present method caninclude proppant and a removable proppant-spacing material, which canfunction to form open channels around the proppant pillars. In someembodiments, these extrametrical channel-forming materials, includingproppant-spacing particles, are referred to herein as “channelant.” Inother embodiments, the extrametrical material may not necessarily serveas a channelant, but may be at least partially, or even totallyremovable under formation conditions, while in some cases theextrametrical material may not be removable.

As used herein, the term “open channels” refers to interconnectedpassageways formed in the proppant-fracture structure. Open channels aredistinct from interstitial passages between individual proppantparticles in the proppant matrix in that the channels fully extendbetween opposing fracture faces, free of obstruction by proppant orother flow-impeding structures, and exist outside the proppant matrix,in some cases laterally bounded by the proppant pillars. Such openchannels generally have a hydraulic radius, and hence a hydraulicconductivity, which is at least an order of magnitude larger than thatof interstitial flow passages through the proppant matrix.

The open channels can be formed by placing the proppant andextrametrical material in the fracture in such a way that thepillar-forming proppant islands are ultimately segregated from thechannel-forming removable material. The segregation can occur or beginin the preparation, mixing or pumping of the treatment fluid, in theinjection of the treatment fluid in the fracture, in or after theproppant placement, packing or settling in the fracture, by a distinctpost-injection step of chemical and/or mechanical manipulation ortreatment of the proppant/extrametrical material following initialplacement in the fracture, or by aggregating and consolidating theproppant during the extrametrical material removal.

As used herein, the terms “segregation,” “segregating” and the likerefer to any heterogeneous proppant/extrametrical material distributionbetween proppant-rich pillar-forming islands or regions andproppant-lean extrametrical material regions. It may not be necessary tokeep the proppant-rich regions entirely free of extrametrical materialbecause the presence of extrametrical material, especially in relativelyminor amounts, may not exceed any level that prevents the formation orconsolidation of the proppant into pillars of sufficient strength toprevent the fracture from closing. In an embodiment, the extrametricalmaterial can function in the proppant or proppant regions to consolidateor reinforce the proppant islands and/or to strengthen the proppantpillars. Conversely, the extrametrical material regions can containproppant particles, especially relatively minor amounts, which remainunconsolidated or do not otherwise prevent removal of the extrametricalmaterial to form the open channels and which do not result inobstruction or excessive clogging of the open channels by the proppant.

A simplified embodiment of the method is illustrated with reference toFIGS. 1-2, in which the extrametrical material particles can begenerally insoluble in the injection fluid and soluble in the formationfluid. In FIG. 1, a wellbore 10 can be completed with perforations 12 information 14. The wellbore is shown as a vertical wellbore for thepurposes of illustration only. The wellbore can be deviated at any anglerelative a vertical wellbore, or any combination of both vertical anddeviated sections. Segregated proppant particles 16 and extrametricalmaterial particles 18 can be injected in a fracturing fluid through thewellbore 10 into a fracture 20, where they can be heterogeneously placedin respective proppant-rich islands 22 spaced apart by extrametricalmaterial-rich regions 24. The fracture 20 can be allowed to close, andthe proppant islands 22 compressed to form pillars to support thefracture 20 and prevent the opposing fracture faces from contacting eachother. Simultaneously, the extrametrical material can be packed in theproppant-lean regions 24 and can help restrict the islands 22 fromcreeping or spreading laterally due to compression by the weight of theformation, thereby facilitating a greater height or open dimension ofthe resulting propped fracture and a greater hydraulic conductivity.

During another operative step, the extrametrical material can be removedin various embodiments by flushing, dissolving, softening, melting,breaking, or degrading the extrametrical material, wholly or partially,via a suitable activation mechanism, such as, but not limited to,temperature, time, pH, salinity, solvent introduction, catalystintroduction, hydrolysis, and the like, or any combination thereof. Theactivation mechanism can be triggered by ambient conditions in theformation, by the invasion of formation fluids, exposure to water,passage of time, by the presence of incipient or delayed reactants in ormixed with the extrametrical material particles, by the post-injectionintroduction of an activating fluid, or the like, or any combination ofthese triggers.

Then, with reference to FIG. 2, the formation fluid can be allowed toinvade the fracture 20 to displace any extrametrical material,extrametrical material solution, extrametrical material degradationproducts, and any unconsolidated proppant or other particles, from theproppant-lean regions. In one embodiment, the extrametrical material cansimply be unconsolidated so that it can be removed hydraulically, or caninclude unconsolidated particles that can be removed hydraulically, e.g.by flushing the fracture with formation fluid and/or an injectedflushing or back-flushing fluid. A network of interconnected openchannels 26 can thus be formed around the pillars 28 to provide thefracture 20 with high conductivity for fluid flow. Fluids can now beproduced from the formation 14, into the fracture 20, through the openchannels 26 and perforations 12, and into the wellbore 10.

The extrametrical material can, in some cases, be removed mechanically,for example by using fluid to push extrametrical material out of theformation. In such instances, the extrametrical material can remain in asolid state from the time of injection through removal from thefracture. Some suitable materials that can resist degradation andcrushing include glass, ceramics, carbon and carbon-based compounds,metals and metallic alloys, naturally occurring and synthetic minerals,and high-density plastics that are oil-resistant and exhibit acrystallinity of greater than about 10%. Some other suitable highdensity plastic materials include nylons, acrylics, styrenes,polyesters, polyethylenes, oil-resistant thermoset resins, andcombinations thereof.

Alternatively, the extrametrical material can be softened, dissolved,reacted or otherwise made to degrade. Materials suitable for dissolvableextrametrical material include for example, and without limitation,polyvinyl alcohol (PVOH) extrametrical materials, salt, wax, calciumcarbonate, and the like and combinations thereof. An oil-degradableextrametrical material can be selected, so that it will be degraded byproduced fluids. Alternatively, an extrametrical material can beselected which is degraded by agents purposefully placed in theformation by injection, wherein mixing the extrametrical material withthe agent induces a delayed reaction degradation of the extrametricalmaterial.

In some embodiments of fracturing operations, a solid acid-precursor canbe used as the degradable extrametrical material. Suitableacid-generating dissolvable extrametrical materials can include forexample, and without limitation, PLA, PGA, carboxylic acid, lactide,glycolide, copolymers of PLA or PGA, and the like and combinationsthereof. Provided that the formation rock is carbonate, dolomite,sandstone, or otherwise acid reactive, then the hydrolyzed product ofthe extrametrical material, a reactive liquid acid, can etch theformation at surfaces exposed between the proppant pillars. This etchingcan enlarge the open channels and thus further enhance the conductivitybetween the pillars. Other uses of the generated acid fluid can includeaiding in the breaking of residual gel, facilitating consolidation ofproppant clusters, curing or softening resin coatings and increasingproppant permeability.

In other embodiments of the disclosure, the extrametrical material maybe formed of, or contain, a fluoride source capable of generatinghydrofluoric acid upon release of fluorine and adequate protonation.Some nonlimiting examples of fluoride sources which are effective forgenerating hydrofluoric acid include but are not limited to fluoboricacid, ammonium fluoride, sodium fluoride, and the like, or any mixturesthereof.

FIGS. 3-4 illustrate the acid etching process for greater fractureconductivity. In reference to FIG. 3, proppant islands 30 areheterogeneously placed in fracture 32 with a degradable solidacid-precursor in the extrametrical material-rich regions 34. Inreference to FIG. 4, delayed hydrolysis of the acid-precursorextrametrical material at formation conditions forms an acid that cutsinto the face of the carbonate formation, resulting in localized etching36 to enlarge the channels 38. The proppant pillars 30 remain intact toprop open the fracture.

The approach of heterogeneous proppant placement (HPP) is embodied insome aspects of embodiments of this disclosure. Heterogeneous proppantpacks, hereinafter referred as proppant pillars, may prevent fractureclosure and provide highly conductive channels around pillars serving asflow path for hydrocarbons. The HPP can result in a number of benefitswhen compared to conventional stimulation treatments, such as but notlimited to increased fracture conductivity, improved fracture clean up,longer effective fracture length, reduced consumption of proppant andothers.

The method of HPP according to some embodiments relies on pulsation ofproppant concentration during fracturing treatment, which results inHPP. Parameters of the treatment schedule may include for example,duration of proppant slurry and clean fluid pulses, proppantconcentration, and carrier fluid design. Optimization of the above andother design parameters, at least in part based on the geomechanicalproperties of a treated reservoir, can significantly enhance fractureconductivity and effective length, eventually leading to hydrocarbonproduction increases.

In some embodiments, the treatment schedule utilizes a proppant pulsingschedule as shown in FIG. 5. The first stage is a proppant free stage,called PAD, which aims to initiate a fracture and helps to define itsgeometry. After that a number of proppant stages may be pumped withincreasing proppant concentration. All or some proppant stages may bepumped in cycles, with every cycle comprising a clean fluid pulse and aproppant slurry pulse of the same or different duration. The proppantconcentration in the proppant slurry pulses is kept similar or the samefor every stage. In the last proppant stage, or otherwise known as a‘Tail-In’, the schedule is pumped without pulses and serves as acoupling between the channeled fracture and a wellbore.

In some methods, pulse duration and proppant concentration may be variedand optimized. Pumping rate may be used a tool, as having the same pulseduration can provide different pulse volumes and correspondinglydifferent spacing between pillars. In some cases, optimization ofvarious pulse/slug volumes and/or durations and/or change pumping ratesduring pulses can be conducted.

Conductivity of a channeled fracture may depend upon the pillar width,the distance between the pillars, the stress exerted by pillars,geomechanical properties of formation and other factors. The pillarwidth may depend upon the concentration of proppant in proppant pulsesand the hydraulic fracture width. Distance between pillars may berelated to clean fluid pulse duration. The stress on pillars can berelated to minimum in-situ stress in formation and percent fracture wallarea covered by pillars.

Some embodiments refer to methods of optimization of the treatmentpumping schedule, in particular on duration of stages, proppantconcentration in pulses and clean fluid/proppant slurry pulse duration,which can provide optimally achievable fracture conductivity. Theinverse approach allows to further define the schedule parameters so toprovide predetermined fracture geometry and conductivity with lessproppant and/or fracturing fluid.

For example, during the treatment a portion of the fracturing fluid mayleak off into the formation. This may result in a fluid efficiencydecrease and may also reduce the distance between proppant pillars inthe fracture with an increase of the proppant concentration. Inaddition, the friction properties of the fracturing fluid (effectiveviscosity) may have an impact on the hydraulic fracture width. Based onsimulations of the leak off and friction properties of the fluid, theproppant concentration in the slurry pulses, as well as the durations ofthe proppant slurry and the clean fluid pulses can be calculated and thefracture conductivity can be further optimized. The schedule parameterscan be further changed during the treatment, to optimally distribute thepillars along the fracture length. One possible implementation is shownas follows:

-   -   A fracture filled with a system of pillars so that there are        open channels remaining between pillars (see FIG. 6). The        distance between pillar edges L is smaller than L₀−the distance        at which the channels begin to close. The ratio of the pillar        area to the area of the pointed square (FIG. 6)        S_(pillar)/S_(cell) determines ratio of area of propped fracture        face to total fracture area. This ratio is related to        T_(prop)/(T_(prop)+T_(clean)) where T_(prop)−time of dirty pulse        and T_(clean)−time of clean pulse. The conductivity K of the        channels between pillars depends on S_(pillar)/S_(cell) and        L/L₀. For certain parameters the conductivity reaches        theoretical maximum K_(max). FIG. 7 illustrates how channel        conductivity may depend upon propped fracture area for different        ratio L/L₀.

In another example, as the fracturing fluid flows in a wellbore and in afracture, the proppant slurry slugs may be affected by dispersion due tomixing with clean fluid at the interfaces between the two, which canresult in increasing proppant slug volume and reduced proppantconcentration in the slug. The degree of slug dispersion at entranceinto formation (perforation clusters), depending on proppantconcentration in the slugs and the slug volume on surface can beoptimized to provide the required pulse parameters. The degree of slugdispersion can be determined from surface and downhole measurements ofpressure, fluid density and/or other parameters, known to those skilledin the art.

In still another example, early proppant stages in hydraulic fracturingtreatments are designed with low proppant concentrations to avoidscreen-out. These stages are intended to place the proppant close to thetip of the fracture, where hydraulic width is small. In the case of HPPachieved by pulsations, channels in the tip area may have higherlikelihood of closure, significantly affecting the fracture conductivityand the effective fracture length. To reduce the risk of losingconductivity in the tip, the pulses of proppant slurry with differentproppant concentrations may be pumped. The closed channels in this casemay then remain propped, providing the conductivity of a homogeneousproppant pack. It is also possible to pump proppant continuously withoutpulses in the beginning of the treatment in order to prop the tip areaand then switch to the optimized pulsed pumping schedule.

In a further example, highly deviated or essentially horizontal wellswith multistage completions may facilitate initiations of multiplefractures during a single treatment. The fracturing fluid and proppantslurry may be distributed between open fractures in some ratios. Thenumber of opened fractures (perforation clusters, accepting fluid) canbe determined by methods, known from the art. This number can be animportant parameter for the pulsing schedule design. Depending on thenumber of fractures, the clean fluid pulse duration can be tuned so asto provide an optimal average distance between pillars in all fractures.Since the number of fractures can change during the treatment(screen-out in some of fractures and/or new fracture opening) thepulsing schedule can be adjusted in the real time.

In a still further example, the practice of hydraulic fracturinginvolves pumping stages with gradually increasing proppantconcentrations. This is done to reduce the risk of premature screen-out,as higher proppant concentration increases fracture conductivity but canalso lead to proppant bridging in the fracture. On the other handpumping of only a portion of proppant slurry pulses with higherconcentration in particular stage can increase fracture conductivitywithout a considerable increase of the prossibility of screen out. Anon-limiting example is during the 3 PPA stage pumping of every thirdslurry pulse with 4 PPA proppant concentration. In this case, proppantinside the fracture will have a higher concentratration, thus thickerpillars will be surrounded by thinner ones. This approach may allow afurther increase of fracture conductivity and effective length withreduced risk of premature screen-out. Furthermore, some of pulses can bedesigned with lower concentrations, e.g. at the same 3 PPA stage, as inthe previous example, every second pulse can be designed at 2 PPA. Thefrequency of lower proppant concentration slurry pulses and the value ofproppant concentration can be designed to provide open channels insidethe fracture. In this case the fracture may have enough conductivity forhigh hydrocarbons production but with using less proppant.

Some other embodiments are methods of creating of a heterogeneousproppant pack in a hydraulic fracture for the case of horizontal wellapplications and therefore a creation of a network of the conductiveopen channels available for fluid flow. Hydraulic fractures covered bysuch a heterogeneous proppant pack may have an essentially higherconductivity than conventional (uniformly propped) fractures andtherefore may increase the oil and gas production rate.

In such embodiments, the method for forming of a heterogeneous proppantpack (HPP) in the fracture is based on the alternate injection into thefracture of a fracturing fluid and a fracturing fluid loaded withproppant. With such a technique it may be important to optimally designthe duration of the alternating stages, and furthermore, introduce thehomogeneous pack nearer to the wellbore to prevent fracture pinching.HPP in horizontal applications hence comprises the following stages:

-   -   1) The first stage is an injection of a fracturing fluid and        formation/propagation of a fracture. The fluid injected at this        stage (pad stage) typically has no propping agent or low        concentration of small size proppant as a loss prevention agent,        or proppant slugs to clean up and erode the perforations, or        proppant to engage parts of the fracture close to the tip.    -   2) The second stage comprises a repetitive addition of given        volumes of the proppant to the fracturing fluid. The given        volume of the proppant, mixed with the fracturing fluid (at        given proppant concentration) is called a proppant pulse (or        sub-stage). The volume or duration of a proppant pulse is an        important parameter and it has essential influence on desired        final properties of the fracture. In order to achieve an        essential conductivity increase, in some cases the timing of a        single slug pumping (on surface) can be less than 60 sec at the        usual pumping rates, and corresponding volume may be less than        80 bbl. Durations between injected proppant pulses may may be        controlling parameters, and, in some examples, are less than 60        sec or in terms of volume, do not exceed 80 bbl. The number of        the proppant pulses injected in the second stage may be high        enough, and may also depend on the size of the fracturing        treatment and designed geometry of the fracture. At the same        time, to achieve the desired fracture conductivity, the number        of the proppant pulses injected in the second stage may        typically exceed 1, 2, 3, or even 4 pulses.    -   3) The third stage (tail-in stage) is the injection of a given        volume of the fracturing fluid with proppant into the fracture.        The proppant injected in this stage forms the stable proppant        pack close to the wellbore to prevent formation walls to close        in the near-wellbore zone. The duration of this stage is a        controlling parameter, which depends upon the mechanical        formation properties and parameters of the treatment. A very        short “tail-in” stage may result in a pinching between the        wellbore and the nearest proppant pulse, pumped in stage 2 (see        FIG. 9, notation #6). At the same time, the HPP located close to        the wellbore may compromise the production, as the conductivity        of this area can be significantly lower than the conductivity of        the channeled part. Hence, the duration of this stage is limited        from the upper end by the production requirement. Summarizing,        the pumping time of the third stage should typically exceed 6        sec (or in terms of volume it should exceed 3 bbl). At the same        time it may be beneficial not to exceed the total pumping time        or the injected volume of stage two (a standard duration pulse).

Methods described hereinabove may be also applicable to simultaneousstimulation of multiple fractures that may occur in the cases ofopen-hole completion and cased-hole with multiple perforation clusters.The volumes of the stages specified above are specified per onefracture. Hence, the on-surface pumping schedule may optimally bemodified, and stage volumes be multiplied by expected number offractures generated by the given treatment.

During hydraulic fracturing, high pressure pumps on the surface injectthe fracturing fluid into a wellbore adjacent to the face or pay zone ofa geologic formation. The first stage, also referred to as the “padstage” (referred to above) involves injecting a fracturing fluid into aborehole at a sufficiently high flow rate and pressure sufficient toliterally break or fracture a portion of surrounding strata at the sandface. The pad stage is pumped until the fracture has sufficientdimensions to accommodate the subsequent slurry pumped in the proppantstage. The volume of the pad can be designed by those knowledgeable inthe art of fracture design, for example, as described in ReservoirStimulation, 3rd Ed., M. J. Economides, K. G. Nolte, Editors, John Wileyand Sons, New York, 2000.

Water-based fracturing fluids are common, with natural or syntheticwater-soluble polymers optionally added to increase fluid viscosity, andcan be used throughout the pad and subsequent proppant and/orextrametrical material stages. These polymers include, but are notlimited to, guar gums; high-molecular-weight polysaccharides composed ofmannose and galactose sugars; or guar derivatives, such as hydroxypropylguar, carboxymethyl guar, carboxymethylhydroxypropyl guar, and the like.Cross-linking agents based on boron, titanium, zirconium or aluminumcomplexes are typically used to increase the effective molecular weightof the polymer for use in high-temperature wells.

To a small extent, cellulose derivatives, such as hydroxyethylcelluloseor hydroxypropylcellulose and carboxymethylhydroxyethylcellulose, may beused with or without cross-linkers. Two biopolymers—xanthan andscleroglucan—provide excellent proppant suspension, but are moreexpensive than guar derivatives and so are used less frequently.Polyacrylamide and polyacrylate polymers and copolymers are typicallyused for high-temperature applications or as friction reducers at lowconcentrations for all temperatures ranges.

Water-based fracturing fluids can also be obtained using viscoelasticsurfactants. Usually, these fluids are prepared by mixing in appropriateamounts of suitable surfactants, such as anionic, cationic, nonionic,amphoteric, and zwiterionic. The viscosity of viscoelastic surfactantfluids are attributed to the three-dimensional structure formed by thefluid's components. When the surfactant concentration in a viscoelasticfluid significantly exceeds a critical concentration, and in most casesin the presence of an electrolyte, surfactant molecules aggregate intospecies, such as worm-like or rod-like micelles, which can interact toform a network exhibiting viscous and elastic behavior. Also,polymer-free clay-based fluids, for example those based on Laponite®(synthetic clay viscosifler) may be useful as well.

After the fracture is induced, proppant and extrametrical material canbe injected into the fracture as a slurry or suspension of particles inthe fracturing fluid during what is referred to herein as a “proppantstage.” In the proppant stage, proppant and extrametrical material canbe injected in one or more segregated substages alternating between a“proppant substage” and a “extrametrical material substage,” and/or as amixture of extrametrical material and proppant in one or more substagesreferred to herein as a “mixed substage.” Further, the proppant,extrametrical material and/or mixed substages can be separated by one ormore optional “carrier substages”, which are substantially free ofproppant and extrametrical material and can also be substantially freeof other particles.

Some embodiments of this disclosure may benefit processes that arerelated to hydraulic fracturing. Examples of these embodiments includeenhanced oil recovery, treatments for waste disposal wells for injectinga storing carbon dioxide, waste water or other liquid waste, andtreatments for wells for environmental remediation i.e. to inject waterto modify the direction or speed of groundwater flow or injection of achemical to clean a polluted aquifer. Some embodiments may benefit fromusing seawater or production water with solids.

As a result, the proppant does not completely fill the fracture. Rather,spaced proppant clusters are formed as pillars, with proppant-spacingextrametrical material initially filling the channels between them. Uponsubsequent removal of the extrametrical material, formation fluids areable to pass through the channels. The volumes of proppant,extrametrical material and carrier sub-stages as pumped can bedifferent. That is, the volume of the extrametrical material and anycarrier substages can be larger or smaller than the volume of theproppant and/or any mixed substages. Furthermore, the volumes and orderof injection of these substages can change over the duration of theproppant stage. That is, proppant substages pumped early in thetreatment can be of a smaller volume than a proppant substage pumpedlater in the treatment. The relative volume of the substages can beselected by an engineer or operator based upon how much of the surfacearea of the fracture is desired to be supported by the clusters ofproppant, and how much of the fracture area is desired as open channelsthrough which formation fluids are free to flow.

Suitable proppants can include sand, gravel, glass beads, ceramics,bauxites, mica, glass, and the like or combinations thereof. Also otherproppants like, plastic beads such as styrene divinylbenzene, andparticulate metals may be used. Proppant used in this embodiments ofthis disclosure may not necessarily require the same permeabilityproperties as typically required in conventional treatments because theoverall fracture permeability will at least partially develop from theformation of channels. Other proppants may be materials such as drillcuttings that are circulated out of the well. Also, naturally occurringparticulate materials may be used as proppants, including, but notnecessarily limited to: ground or crushed shells of nuts such as walnut,coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or crushedseed shells (including fruit pits) of seeds of fruits such as plum,olive, peach, cherry, apricot, etc.; ground or crushed seed shells ofother plants such as maize (e.g., corn cobs or corn kernels), etc.;processed wood materials such as those derived from woods such as oak,hickory, walnut, poplar, mahogany, etc., including such woods that havebeen processed by grinding, chipping, or other form of particalization,processing, etc, some nonlimiting examples of which are proppants madeof walnut hulls impregnated and encapsulated with resins. Furtherinformation on some of the above-noted compositions thereof may be foundin Encyclopedia of Chemical Technology, Edited by Raymond E. Kirk andDonald F. Othmer, Third Edition, John Wiley & Sons, Volume 16, pages248-273 (entitled “Nuts”), Copyright 1981, which is incorporated hereinby reference. Resin coated (various resin and plastic coatings) orencapsulated proppants having a base of any of the previously listedpropping materials such as sand, ceramics, bauxite, nut shells, etc. maybe used in accordance with embodiments of this disclosure. Essentially,a proppant can be any material that will function to hold open thepropped portion of the fracture.

The selection of proppant can balance the factors, for example, ofproppant long-term strength, proppant distribution characteristics andproppant cost. The proppant can have the ability to flow deeply into thehydraulic fracture and form spaced pillars that resist crushing uponbeing subjected to the fracture closure stress. Relatively inexpensive,low-strength materials, such as sand, among others, can be used forhydraulic fracturing of formations with small internal stresses.Materials of greater cost, such as ceramics, bauxites and others, can beused in formations with higher internal stresses. Further, the chemicalinteraction between produced fluids and proppants, which cansignificantly change the characteristics of the proppant, can beconsidered as selection criteria.

Because an embodiment does not need to rely on the porosity orpermeability of the packed proppant matrix to impart flow conductivityto the fracture, the availability for selection of a wide range ofproppant materials can benefit a range of applications and costrestrictions. For example, a proppant can have a variety of sizes orrange of mixed, variable diameters or other properties that yield ahigh-density, high-strength pillar, which can form a proppant matrixthat has high or low porosity and high or low permeability. Proppantporosity and permeability are not as critical in an embodiment of thisdisclosure because fluid production is not required to flow through theproppant matrix. Another option for section is an adhesive orreinforcing material that would plug a conventional proppant pack. Theadhesive or reinforcing material can be employed in the interstitialspaces of the proppant matrix herein, such as, for example, a settableor crosslinkable polymer which can be set or crosslinked in theproppant.

Accordingly for example, a proppant pillar of suitable strength can besuccessfully created using sand with particles considered too weak foruse in conventional hydraulic fracturing. The relative costs of sand aresubstantially less than ceramic proppant. Additionally, destruction ofsand particles during application of the fracture closure load canimprove the strength behavior of the same cluster consisting of proppantgranules. This can occur because the cracking/destruction of proppantparticles decreases the cluster porosity thereby compacting theproppant. Sand pumped into the fracture to create proppant clusters doesnot need good granulometric properties, that is, the narrow particlesize or diameter distribution required for a permeable proppant pack inconventional fracturing. For example, in one embodiment, it is possibleto use 50 tons of sand, wherein 10 to 15 tons have a diameter ofparticles from 0.002 to 0.1 mm, 15 to 30 tons have a diameter ofparticles from 0.2 to 0.6 mm, and 10 to 15 tons have a diameter ofparticles from 0.005 to 0.05 mm. It should be noted that conventionalhydraulic fracturing would require about 100 tons of a proppant moreexpensive than sand to obtain a similar value of hydraulic conductivityfor fluid passage through the continuous-porosity proppant matrix in thepropped fracture.

For the purposes of this disclosure, one embodiment of the proppant canuse sand with an adhesive coating alone, or an adhesive coating coatedwith a layer of non-adhesive substance dissolvable while in the fractureas a fracture treatment fluid or another fluid is passed through thefracture. A non-adhesive substance inhibits the formation of proppantagglomerates prior to entering the fracture, and allows for controllingthe moment of time in the fracture when a proppant particle gains itsadhesive properties. The moment of time corresponds to the location ofthe proppant within the fracture. The adhesive coating can be cured atthe formation temperature, and sand particles conglutinate between eachother. Bonding particles within the pillars can inhibit erosion of theproppant pillar as formation fluids flow past, thereby minimizingsubsequent proppant island destruction by erosion.

In one embodiment, reinforcing and/or consolidating material can beintroduced into the fracture fluid to increase the strength of theformed proppant clusters and preventing their collapse during fractureclosure. Typically the reinforcement material can be added to theproppant substage and/or the mixed substage, but could also beintroduced additionally or alternatively in the extrametrical materialsubstage and/or the carrier substage, or in other ways. For example, thereinforcement material can be an extrametrical material that serves toreinforce the proppant clusters, but can be removed as or with theextrametrical material from the proppant-lean regions. Theconcentrations of both proppant and the reinforcing materials can varyin time throughout the proppant stage, and from substage to substage.That is, the concentration of proppant reinforcing material can bedifferent at two subsequent substages. It can also be suitable in someapplications of an embodiment of a method to introduce the reinforcingmaterial in a continuous or semi-continuous fashion throughout theproppant stage, during a plurality of adjacent carrier, extrametricalmaterial, mixed and proppant substages. For example, the reinforcingmaterial deposited in the extrametrical material regions in the fracturecan be removed with the extrametrical material as described below. Inany case, introduction of the reinforcing material need not be limitedonly to the proppant substage. Particularly, different implementationscan be considered where the concentration of the reinforcing materialdoes not vary during the entire proppant stage; monotonically increasesduring the proppant stage; or monotonically decreases during theproppant stage.

Curable or partially curable, resin-coated proppant can be used asreinforcing and consolidating material to form proppant clusters. Theselection process of an appropriate resin-coated proppant for aparticular bottom hole static temperature (BHST), and the particularfracturing fluid may be known to experienced workers. In addition,organic and/or inorganic extrametrical materials can reinforce theproppant cluster. These materials can be used in combination withresin-coated proppants or separately. These extrametrical materials canhave an inherently adhesive surface, can be chemically or physicallymodified to have an adhesive coating, or can have an adhesive coatingresulting from a layer of non-adhesive substance dissolvable in thefracture by a fluid simultaneously or subsequently passed through thefracture. Extrametrical materials made of adhesive material can be usedas reinforcing material, coated by a non-adhesive substance thatdissolves in the fracturing fluid or another fluid as it passes throughthe fracture at the subterranean temperatures. Metallic particles areanother embodiment for reinforcing material and can be produced usingaluminum, steel optionally containing special additives that inhibitcorrosion, and other metals and alloys, and the like. The metallicparticles can be shaped to resemble a sphere and in some cases canmeasure 0.1-4 mm, for example. In one embodiment, metallic particles mayhave an elongated shape with a length longer than 2 mm and a diameter of10 to 200 microns. In another embodiment, plates of organic or inorganicsubstances, ceramics, metals or metal-based alloys can be used asreinforcing material in the proppant. These plates can be disk orrectangular-shaped and of a length and width such that for all materialsthe ratio between any two of the three dimensions is greater than 5 to1.

On the other hand, a high permeability and/or high porosity proppantpack can be suitably employed in some situations. In one embodiment, thepermeability of the proppant can provide some limited fractureconductivity in the event the channels are not properly formed or do notfully interconnect. Additionally, under some formation conditions it canbe advantageous when using some embodiments of the present method toperform a final tail-in stage of the fracturing treatment involvingcontinuous proppant introduction into the fracturing fluid, with theproppant at this stage consisting essentially of uniform particle sizeto obtain a zone of continuous-porosity proppant adjacent to thewellbore. If employed, the tail-in stage of the fracturing treatmentresembles a conventional fracturing treatment, where a continuous bed ofwell-sorted conventional proppant is placed in the fracture proximate tothe wellbore. The tail-in stage can involve introduction of both anagent that increases the proppant transport capability of the treatmentfluid and/or an agent that acts as a reinforcing material. The tail-instage is distinguished from the second stage by the continuous placementof a well-sorted proppant, that is, a proppant with an essentiallyuniform particle size, or even a rod-shaped proppant. The proppantstrength should be sufficient to prevent its cracking (crumbling) whensubjected to stresses that occur at fracture closure. The role of theproppant at this tail stage is to prevent fracture closure and,therefore, to provide good fracture conductivity relatively close to thewellbore.

The proppants useful in some embodiments of the present method shouldalso be capable of being segregated into proppant-rich islands forheterogeneous placement in the fracture spaced away from adjacentproppant islands. Properties such as density, size, shape, magneticcharacteristics, and surface characteristics, for example, hydroaffinityand reactivity, and chemical or mechanical interaction with theextrametrical material, and the like, can all influence thesegregability of the proppant. Therefore, these characteristics may beconsidered as selection criteria to facilitate segregation from theextrametrical material-rich regions depending on a variety ofconditions, such as the manner in which segregation is effected,downhole conditions, the extrametrical material, the treatment fluid,etc.

In an embodiment, the proppant can have a self-adherent surface, forexample, by using a proppant that has a natural attraction for or atendency to agglomerate with or adhere to other proppant particles,and/or by coating or chemically modifying the surface of the proppantfor self-adhesion, e.g. by coating the proppant with an adhesive ortackifier, or grafting an adhesive or tackifying compound to theproppant. In some cases, the self-adherent proppant is non-adherent tothe extrametrical material and other surfaces such as the surfacepiping, pumps and wellbore tubing, among others. In one version of theself-adherent proppant, the proppant is loosely held together incohesive slugs or globules of a gel or a lightly crosslinked, flowablepolymer for which the proppant has a differential affinity, e.g. theproppant can be grafted to the gel-forming polymer.

In other embodiments, the proppant can be hydrophilic, for example, byusing a proppant that is normally hydrophilic, such as most sand, forexample, and/or by treating the proppant particles with ionic or polarmodifiers such as a strong acid, weak acid, strong base, weak base, orreacting the surface of the proppant to associate an ionic or polarmoiety with an affinity to aqueous liquids. In this manner, the proppantcan be differentially attracted to other hydrophilic species in thetreatment fluid, e.g. other proppant particles or an immiscible fluidphase in the treatment fluid, such as an aqueous phase, especially wherethe extrametrical material is hydrophobic and/or introduced via animmiscible hydrophobic fluid phase in the treatment fluid.

In still other embodiments, the proppant can be rendered hydrophobic,for example, by using proppant that is normally hydrophobic, such aswax, for example, and/or by treating the proppant particles with oil,wax or other hydrocarbon, or reacting the surface of the proppant toassociate a hydrocarbyl moiety with a low affinity to aqueous liquids.In this manner, the proppant can be differentially attracted to otherhydrophobic species in the treatment fluid, e.g. other proppantparticles or an immiscible fluid phase in the treatment fluid, such asoil or other non-aqueous phase, especially where the extrametricalmaterial is hydrophilic and/or introduced via an immiscible hydrophilicfluid phase in the treatment fluid.

In further embodiments the proppant can be present in a treatment fluidthat is injected into the fracture in the form of an immiscible fluidpacket or globule dispersed in a more or less continuous phase of asecond fluid carrying the extrametrical material. The immiscible fluidproppant packets can each contain a sufficient quantity of proppant toform a suitably sized island, singly from isolated packet placement orin combination with one or more additional proppant packets wherecumulative packet placement can occur. Because the open channels to beformed must interconnect between the wellbore and the remote exposedsurfaces in the fracture, it can be convenient to provide theextrametrical material in a continuous phase in the treatment fluid inwhich the proppant packets are in a dispersed or discontinuous phase. Inone version, the proppant packets can be provided with a thinencapsulating skin or deformable bladder to retain or group the proppantand configured to remain flowable during injection, and the bladder canbe optionally ruptured or chemically or thermally removed duringplacement in the fracture and/or during closure of the fracture.

The choice of extrametrical material can depend on the mode ofextrametrical material segregation and placement in the fracture, aswell as the mode of extrametrical material removal and channelformation. In its simplest form, the extrametrical material can be asolid particulate that can be maintained in its solid form duringinjection and fracture closure, and readily dissolved or degraded forremoval. Materials that can be used can be organic, inorganic, glass,ceramic, nylon, carbon, metallic, and so on. Suitable materials caninclude water- or hydrocarbon-soluble solids such as, for example, salt,calcium carbonate, wax, or the like. Polymers can be used in anotherembodiment, including polymers such as polylactic acid (PLA),polyglycolic acid (PGA), polyol, polyethylene terephthalate (PET),polysaccharide, wax, salt, calcium carbonate, benzoic acid, naphthalenebased materials, magnesium oxide, sodium bicarbonate, soluble resins,sodium chloride, calcium chloride, ammonium sulfate, and the like, andso on, or any combinations thereof. As used herein, “polymers” includesboth homopolymers and copolymers of the indicated monomer with one ormore comonomers, including graft, block and random copolymers. Thepolymers can be linear, branched, star, crosslinked, derivitized, and soon, as desired. The extrametrical material can be selected to have asize and shape similar or dissimilar to the size and shape of theproppant particles as needed to facilitate segregation from theproppant. Extrametrical material particle shapes can include, forexample, fibers, spheres, rods, platelets, ribbons, and the like andcombinations thereof. In some applications, bundles of fibers, orfibrous or deformable materials, can be used. These fibers canadditionally or alternatively form a three-dimensional network,reinforcing the proppant and limiting its flowback.

For example, the separation of injected proppant and extrametricalmaterial as introduced and placed in the fracture can be induced bydifferences (or similarities) in size, density or shape of the twomaterials. The specific gravities and the volume concentrations ofproppant and extrametrical material can be tailored to minimize mixingand homogenization during placement. Properly sizing the extrametricalmaterial or adding various weighting agents to the extrametricalmaterial-rich fluid can facilitate segregation at the appropriate timeand location.

Either the proppant or the proppant-spacing particles can also be madeto be “sticky”, so particles of similar material adhere to one another,helping ensure heterogeneity between the two dissimilar materials.Proppant particles can be selected that adhere to other proppantparticles as discussed above and are repelled by or repel theextrametrical material particles. Alternatively, or additionally,extrametrical material particles can be selected that are self-adherentand non-adherent to the proppant. The extrametrical material can, forexample, include a self-adherent coating. Another technique to encourageseparation of the two materials is selecting proppant and extrametricalmaterial with inherent hydroaffinity differences, or creating surfacehydroaffinity differences by treating either the proppant or theextrametrical material with hydrophobic or hydrophilic coatings.

The presence of the extrametrical material in the fracturing fluid inthe proppant stage, e.g. in a mixed substage or in a segregatedextrametrical material substage, can have the benefit of increasing theproppant transport capability. In other words, the extrametricalmaterial can reduce the settling rate of proppant in the fracturetreatment fluid. The extrametrical material in an embodiment may be amaterial with elongated particles having a length that much exceeds adiameter. This material can affect the rheological properties andsuppress convection in the fluid, which can result in a decrease of theproppant settling rate in the fracture fluid and maintain segregation ofthe proppant from proppant lean regions. The extrametrical material canbe capable of decomposing in the water-based fracturing fluid or in thedownhole fluid, such as fibers made on the basis of polylactic acid(PLA), polyglycolic acid (PGA), polyvinyl alcohol (PVOH), and others.

The fibers can be made of or coated by a material that becomes adhesiveat subterranean formation temperatures. They can be made of adhesivematerial coated by a non-adhesive substance that dissolves in thefracturing fluid or another fluid as it is passed through the fracture.The fibers used in one embodiment can be up to 2 mm long with a diameterof 10-200 microns, in accordance with a guideline that the ratio betweenany two of the three dimensions be greater than 5 to 1. In anotherembodiment, the fibers can have a length greater than 1 mm, such as, forexample, 1-30 mm, 2-25 mm or 3-18 mm, or in some cases about 6 mm; andthey can have a diameter of 5-100 microns and/or a denier of about0.1-20, or in some cases about 0.15-6. These fibers are desired tofacilitate proppant carrying capability of the treatment fluid withreduced levels of fluid viscosifying polymers or surfactants. Fibercross-sections need not be circular and fibers need not be straight. Iffibrillated fibers are used, the diameters of the individual fibrils canbe much smaller than the aforementioned fiber diameters.

The concentration of the extrametrical material in the treatment fluidcan conveniently be such that the extrametrical material compressedbetween the proppant islands by fracture closure has a packed volume tofill the spaces between the packed proppant islands at a stress similarto the proppant. In other words, the extrametrical material fill servesto hold the proppant islands in place and inhibit lateral expansion thatwould otherwise reduce the ultimate height of the proppant pillar. Theweight concentration of the fibrous extrametrical material in thefracturing fluid can be from 0.1 to 10 percent in some applications. Theconcentration of the solid extrametrical material in the treatment fluidmay be from about 0.6 g/L (about 5 ppt) to about 9.6 g/L (about 80 ppt).

In an embodiment, a first type of fiber additive can providereinforcement and consolidation of the proppant. This fiber type caninclude, for example, glass, ceramics, carbon and carbon-basedcompounds, metals and metallic alloys, and the like and combinationsthereof, as a material that is packed in the proppant to strengthen theproppant pillars. In other applications, a second type of fiber can beused that inhibits settling of the proppant in the treatment fluid. Thesecond fiber type can include, for example, polylactic acid,polyglycolic acid, polyethylene terephthalate (PET), polyol, nylon, andthe like and combinations thereof, as a material that inhibits settlingor dispersion of the proppant in the treatment fluid and serves as aprimary removable fill material in the spaces between the pillars. Yetstill other applications may include a mixture of the first and secondfiber types, the first fiber type providing reinforcement andconsolidation of the proppant and the second fiber type inhibitingsettling of the proppant in the treatment fluid.

The fibers can be hydrophilic or hydrophobic in nature. Hydrophilicfibers may be considered for a number of applications. Fibers can be anyfibrous material, such as, but not necessarily limited to, naturalorganic fibers, comminuted plant materials, synthetic polymer fibers (bynon-limiting example polyester, polyaramide, polyamide, novoloid or anovoloid-type polymer), fibrillated synthetic organic fibers, ceramicfibers, inorganic fibers, metal fibers, metal filaments, carbon fibers,glass fibers, ceramic fibers, natural polymer fibers, and any mixturesthereof. Particularly useful fibers are polyester fibers coated to behighly hydrophilic, such as, but not limited to, DACRON® polyethyleneterephthalate (PET) Fibers available from Invista Corp. Wichita, Kans.,USA, 67220. Other examples of useful fibers include, but are not limitedto, polylactic acid polyester fibers, polyglycolic acid polyesterfibers, polyvinyl alcohol fibers, and the like.

In some embodiments, the solid extrametrical material is selected fromsubstituted and unsubstituted lactide, glycolide, polylactic acid,polyglycolic acid, copolymers of polylactic acid and polyglycolic acid,copolymers of glycolic acid with other hydroxy-, carboxylic acid-, orhydroxycarboxylic acid-containing moieties, copolymers of lactic acidwith other hydroxy-, carboxylic acid-, or hydroxycarboxylicacid-containing moieties, and mixtures of such materials. Some examplesare polyglycolic acid or PGA, and polylactic acid or PLA. Thesematerials may function as solid-acid precursors, and upon dissolution inthe fracture, can form acid species that can perform secondary functionsin the fracture.

If desired, a pH control agent can be used in the treatment fluid,especially where a solid acid precursor is present and one or more ofthe other treatment fluids is pH-sensitive. The pH control agent can beselected from amines and alkaline earth, ammonium and alkali metal saltsof sesquicarbonates, carbonates, oxalates, hydroxides, oxides,bicarbonates, and organic carboxylates, for example sodiumsesquicarbonate, triethanolamine, or tetraethylenepentamine.

For example, the extrametrical material can function as an acid breakerfor a viscosifying agent, where the extrametrical material is selectedfrom a solid that contains an acid and that hydrolyzes to release anacid, a solid that hydrolyzes to release an acid, or mixtures of suchmaterials. The solid can be present in particles sufficiently small thatthey at least partially enter the pores of the formation, and/orsufficiently large that they remain in the fracture in the spacesbetween the proppant pillars. The treatment fluid can also contain a pHcontrol agent present in an amount sufficient to neutralize any acidpresent in the solid material before the injection and to neutralize anyacid generated by the solid material during the injection, so that theacid breaker is not available to break the fluid during the injection.When the injection is stopped, the solid may be allowed to release acidin excess of the amount that can be neutralized by any pH control agent,thereby breaking the viscous fluid.

Optionally, the viscosifying agent in some embodiments may be aviscoelastic surfactant system. Also optionally, the solid material maybe of a size that forms an internal filter cake in the pores of theformation. Still further optionally, the solid material may be of a sizethat does not block the flow of fluid in the pores of the formation. Thesolid material is selected from substituted and unsubstituted lactide,glycolide, polylactic acid, polyglycolic acid, copolymers of polylacticacid and polyglycolic acid, copolymers of glycolic acid with otherhydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containingmoieties, copolymers of lactic acid with other hydroxy-, carboxylicacid-, or hydroxycarboxylic acid-containing moieties, and mixtures ofsuch materials. An example used in some embodiments is polyglycolicacid. The pH control agent is selected from amines and alkaline earth,ammonium and alkali metal salts of sesquicarbonates, carbonates,oxalates, hydroxides, oxides, bicarbonates, and organic carboxylates,for example sodium sesquicarbonate, triethanolamine, ortetraethylenepentamine.

Suitable solid acids for use in viscoelastic surfactant (VES) fluidsystems include substituted and unsubstituted lactide, glycolide,polylactic acid, polyglycolic acid, a copolymer of polylactic acid andpolyglycolic acid, a copolymer of glycolic acid with other hydroxy-,carboxylic acid-, or hydroxycarboxylic acid-containing moieties, acopolymer of lactic acid with other hydroxy-, carboxylic acid orhydroxycarboxylic acid-containing moieties, or mixtures of thepreceding. Other materials suitable for use in VES fluid systems are allthose polymers of hydroxyacetic acid (glycolic acid) with itself orother hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containingmoieties described in U.S. Pat. Nos. 4,848,467; 4,957,165; and4,986,355, all three hereby incorporated by reference. Suitable solidacids are also described in U. S. Patent Application Publication Nos.2003/002195 and 2004/0152601, both of which are hereby incorporated byreference and are assigned to the assignee of the present disclosure.

In some applications, suitable solid acid components for VES systems aresolid cyclic dimers, or solid polymers, of certain organic acids, thathydrolyze under known and controllable conditions of temperature, timeand pH to form organic acids. One example, a suitable solid acid is thesolid cyclic dimer of lactic acid known as “lactide”, which has amelting point of 95 to 125° C. depending upon the optical activity.Another is a polymer of lactic acid, sometimes called a polylactic acidor “PLA”, or a polylactate, or a polylactide. Another example is thesolid cyclic dimer of glycolic acid known as “glycolide”, which has amelting point of about 86° C. Yet another example is a polymer ofglycolic acid (hydroxyacetic acid), also known as polyglycolic acid(“PGA”), or polyglycolide. Another example is a copolymer of lactic acidand glycolic acid. These polymers and copolymers are polyesters. Theas-received materials can contain some free acid and some solvent,typically water.

Natureworks L.L.C., Minnetonka, Minn., USA, produces a solid cycliclactic acid dimer called “lactide” and from it produces lactic acidpolymers, or polylactates, with varying molecular weights and degrees ofcrystallinity, under the generic trade name NATUREWORKS™ PLA. The PLA'scurrently available from Cargill Dow have molecular weights of up toabout 100,000, although any polylactide (made by any process by anymanufacturer) and any molecular weight material of any degree ofcrystallinity can be used in the embodiments of this disclosure. The PLApolymers are solids at room temperature and are hydrolyzed by water toform lactic acid. Those available from Cargill Dow typically havecrystalline melt temperatures of from about 120 to about 170° C., butothers are obtainable.

Poly(d,l-lactide) is available from Bio-Invigor, Beijing and Taiwan,with molecular weights of up to 500,000. Bio-Invigor also suppliespolyglycolic acid (also known as polyglycolide) and various copolymersof lactic acid and glycolic acid, often called “polyglactin” orpoly(lactide-co-glycolide). The rates of the hydrolysis reactions of allof these materials are governed, among other factors, by the molecularweight, the crystallinity (the ratio of crystalline to amorphousmaterial), the physical form (size and shape of the solid), and in thecase of polylactide, the amounts of the two optical isomers. (Thenaturally occurring l-lactide forms partially crystalline polymers;synthetic dl-lactide forms amorphous polymers.) Amorphous regions aremore susceptible to hydrolysis than crystalline regions. Lower molecularweight, less crystallinity and greater surface-to-mass ratio can resultin faster hydrolysis. Hydrolysis can also be accelerated by increasingthe temperature, by adding acid or base, or by adding a material thatreacts with the hydrolysis product(s).

Homopolymers of PGA and PLA can be more crystalline; copolymers tend tobe amorphous unless they are block copolymers. The extent of thecrystallinity can be controlled by the manufacturing method forhomopolymers and by the manufacturing method and the ratio anddistribution of lactide and glycolide for the copolymers. Polyglycolidecan be made in a porous form. Some of the polymers dissolve very slowlyin water before they hydrolyze; it is to be understood that the termshydrolyze or hydrolysis, etc., are intended to include dissolution.

The solid acids can be coated to slow the hydrolysis. Suitable coatingsinclude polycaprolate (a copolymer of glycolide andepsilon-caprolactone), and calcium stearate, both of which arehydrophobic. Polycaprolate itself slowly hydrolyzes. Generating ahydrophobic layer on the surface of the solid acids by any means canfacilitate segregation from hydrophilic proppant and can delay thehydrolysis for injection and fracture. Note that coating here can referto encapsulation or simply to changing the surface by chemical reactionor by forming or adding a thin film of another material. Anothersuitable method of delaying the hydrolysis of the solid acid, and therelease of acid, is to suspend the solid acid, optionally with ahydrophobic coating, in oil or in the oil phase of an emulsion. Thehydrolysis and acid release do not occur until water contacts the solidacid.

The VES self-destructs in situ, that is, in the location where it isplaced. That location can be part of a suspension in a treatment fluidin the wellbore, in perforations, in a gravel pack, or in a fracture; oras a component of a filter cake on the walls of a wellbore or of afracture; or in the pores of a formation itself The VES can be used informations of any lithology but are used most commonly in carbonates orsandstones.

A particular advantage of these materials is that the solid acidprecursors and the generated acids are non-toxic and are biodegradable.The solid acids are often used as self-dissolving sutures in medicalpractice, for example.

A polyol is a polyhydric alcohol, i.e., one containing three or morehydroxyl groups. One embodiment of a polyol useful as a extrametricalmaterial is a polymeric polyol solubilizable upon heating, desalinationor a combination thereof, and which consists essentially ofhydroxyl-substituted carbon atoms, in a polymer chain, spaced fromadjacent hydroxyl-substituted carbon atoms by at least one carbon atomin the polymer chain. In other words, the useful polyols are essentiallyfree of adjacent hydroxyl substituents. In one embodiment, the polyolhas a weight average molecular weight greater than 5000 up to 500,000 ormore, and from 10,000 to 200,000 in some applictions. The polyol can behydrophobically modified if desired to further inhibit or delaysolubilization, e.g. by including hydrocarbyl substituents such asalkyl, aryl, alkaryl or aralkyl moieties and/or side chains having from2 to 30 carbon atoms. The polyol can also be modified to includecarboxylic acid, thiol, paraffin, silane, sulfuric acid, acetoacetylate,polyethylene oxide, or quaternary amine or other cationic monomers. Suchmodifications have several affects on the properties of the polyol;affects on solubility, sensitivity to salinity, pH, and crosslinkingfunctionalities (e.g. hydroxyl groups and silanol groups which arechelates that can crosslink with common crosslinkers) are of mostinterest to the present disclosure. All of said modifications arecommercially available products.

In one embodiment, the polyol is a substituted or unsubstitutedpolyvinyl alcohol that can be prepared by at least partial hydrolysis ofa precursor polyvinyl compound having ester substituents, such as, forexample, polyvinyl acetate, polyvinyl propanoate, polyvinyl butanoate,polyvinyl pentanoate, polyvinyl hexanoate, polyvinyl 2-methyl butanoate,polyvinyl 3-ethylpentanoate, polyvinyl 3-ethylhexanoate, and the like,and combinations thereof. When the polyol comprises polyvinyl alcoholprepared by at least partial hydrolysis of polyvinyl acetate, the polyolis not generally soluble in salt water, as discussed in more detailbelow, and further, the polyol is commercially available in the form ofpartially crystalline fibers that have a relatively sharp triggertemperature below which the fibers are not soluble in water and abovewhich they readily dissolve, also as discussed in more detail below.

Suitable repeating units in the polyols can have the following formulae:

Polymers can contain units 1 and 2 in varying proportions, where R1 andR1′ can be the same or different, but in some cases the same. In thestructures, R₁ or R₁′ is an alkyl chain that can be saturated orunsaturated, linear or branched, containing 1 to 5 carbon atoms, where nand n′=1 to 5, and where n and n′ can be equal or different, but in somecases equal. R₂ is an alkyl chain that can be saturated or unsaturated,aliphatic or aromatic, linear or branched, from 0 carbons (i.e.hydrogen) to 12 carbons. In the formulae above, m=0 to 5,000 and m′=100to 10,000. The units 1 and 2 can be alternating, random or block inconfiguration.

From the above general description, polymers can be defined by changingparameters. For example, polyvinyl alcohol 99.99% hydrolysis with MW of˜5000 would be: m=0, R1′=CH₂, n′=1, m′=100. Polyvinyl alcohol with 90%hydrolysis and MW of ˜5000 and derived from polyvinyl acetate would be:m=˜10, n=n′=1, R1 =R1′=CH₂, R2=CH₃, m′=˜90.

For the purpose of illustration only, embodiments of this disclosure aredescribed hereafter with reference to polyvinyl alcohol (PVOH) as oneexample of a suitable polyol extrametrical material. Those skilled inthe art will appreciate that embodiments of the present disclosure arenot limited to PVOH and is equally applicable to polyols that meet theabove-stated criteria of having alterable solubility modes in thecontext of well treatment fluids and heterogeneous proppant placementmethodology described herein.

A benefit of PVOH is that it is non-toxic and is biodegradable. Forexample, PVOH is commonly found in the medical industry and fiber formsare commonly used in clothing or fabrics that are intended to dissolvewhen washed in warm or hot water.

PVOH is a solid material that is manufactured in many forms, such as,for example, fibers, sheets, granules, beads, powder, and the like. PVOHis a synthetic polymer that is water soluble and generally unaffected bypetroleum hydrocarbons. The polymer comprises a carbon chain backbonewith hydroxyl and acetate groups. According to Kirk et al., Encyclopediaof Chemical Technology, 3^(rd) Edition, Vol. 23, John Wiley and Sons,pp. 848-865 (1983), PVOH can be produced by the hydrolysis of polyvinylacetate in methanol catalyzed by a base according to the followingequation:

PVOH can generally exist in three different aggregation states, whichmay be controlled by solution conditions. In its solid state, PVOH issemi-crystalline. The degree of crystallinity varies from one mode ofmanufacture to another and with the degree of hydrolysis and grade ofthe PVOH. In aqueous solution, PVOH can lose crystallinity and swell toform an amorphous structure, which is flexible and malleable, but notyet solubilized. Depending on solution conditions, PVOH can solubilizecompletely and exist as polymer stands in solution.

Embodiments of the present disclosure can use PVOH in an insoluble formto place the PVOH extrametrical material downhole in the fracture. Bychanging the salinity and/or temperature conditions adjacent the PVOHdeposited in the fracture, the PVOH can be solubilized to remove thePVOH deposits and/or to activate the PVOH for use as a breaker or otherdownhole function. In addition to the channel-filling material, any PVOHfilter cake can thus also be removed. The PVOH can also be employed as afiber for fiber assisted transport of the proppant, for example.Solubilized PVOH can also function as a delayed breaker for crosslinkedpolymer or viscoelastic surfactant (VES fluid systems), for example.

Embodiments of disclosed methods can exploit the controllability of thesolubility of PVOH and similar polyols in aqueous media by the fluidsalt content. In a brine of sufficiently high salt concentration, PVOHis insoluble but will become a sticky, flexible material that readilybonds to itself and to solid surfaces, allowing it to function as achannel filler material. By dropping the brine concentration below acritical salt level, however, the self-adherent PVOH solids can becomesoluble and rapidly dissolve into solution.

Dissolution of PVOH is controlled by the degree of hydrolysis of thePVOH, molecular weight, crystallinity, particle size, and the like. Thedegree of hydrolysis is defined as the mole percent of hydroxyl groupson the polymer chain in relation to the non-hydrolyzed acetate groups.For example, PVOH with a degree of hydrolysis of 88 would have 88 molepercent hydroxyl groups and 12 mole percent acetate groups along thepolymer backbone. The hydroxyl and/or acetate groups can be distributedrandomly or in blocks.

Most PVOH grades dissolve at around 80° C. (176° F.). A degree ofhydrolysis of about 88% is optimum for solubility in some cases, i.e.the solubility of the PVOH decreases when the degree of hydrolysis ismore or less than about 88%. As the degree of hydrolysis increases above88%, solubility decreases due to a tighter alignment of the hydroxylmoieties which is thought to result from a form of hydrogen bonding.Below 88% hydrolysis, solubility decreases due to the increased numberof acetate groups; polyvinyl acetate is generally insoluble in water.Other factors affecting PVOH solubility can include polymerconcentration and salt concentration; the amount of unsolubilized PVOH,e.g. amorphous PVOH, can increase with increased concentrations of saltor polymer. The crystallinity of the PVOH can also be used to controlthe temperature at which the PVOH will dissolve. For example, PVOH'sthat are partially crystalline to varying extents can be soluble inwater at temperatures ranging from 20° C. to 90° C. As part of thedissolution process PVOH goes through a “glue like” or amorphous state.The solubility and the glue state of PVOH polymer can also be controlledthrough salt concentration. For example, a PVOH fiber that completelydissolves in 2 wt % KCl brine at 80° C. (176° F.), may not completelydissolve below 93° C. (200° F.) in 6% KCl brine, may only deform andclump at 93° C. (200° F.) in 10% KCl brine, and may not be affected atall at 93° C. (200° F.) in 12% KCl brine.

The conditions and rate of dissolution of PVOH, having a particularchemical and physical make-up, including crystallinity, degree ofhydrolysis, molecular weight and distribution, a coating if present, ata particular temperature and in contact with a fluid or fluids of aparticular salinity, is readily determined by a simple experiment:exposing the PVOH to the fluid or fluids under treatment conditions andmonitoring the solubilization.

The PVOH can be manufactured and used in various solid shapes,including, but not limited to fibers, powders, granules, and the like.The system comprising a well treatment fluid and PVOH (and any otheradditives) can be batch-mixed or mixed on-the-fly using otherwiseconventional treatment fluid mixing equipment and mixing techniques.

If the PVOH is in crystalline fiber form that is used primarily belowits trigger temperature for placement and does not swell or becomeamorphous until just before downhole solubilization, then most commonly,straight fibers are used; however, curved, crimped, spiral-shaped andother three dimensional fiber geometries are useful. Also, the fiberscan be bundled together, or hoed on one or both ends. In one embodiment,the fiber length is at least about 2 millimeters, and the fiber diameterranges from about 3 to about 200 microns. There appears to be no upperlimit on the length of the fibers employed from the standpoint ofutility. Handling, mixing, and pumping equipment dictate the practicalupper limit for the length of fibers. Suitable PVOH fibers in oneembodiment have a length of about 2-25 mm, in other embodiments about3-18 mm, and in still other embodiments about 6 mm; they have a denierof about 0.1-20, in some cases about 0.15-6 Such fibers are optimizedfor particle transport.

If the PVOH is amorphous or changes from crystalline to amorphous formin the well treatment fluid, the particular physical form is lesscritical since the PVOH will form a gluelike phase that will disperse assmall particles in the treatment fluid. If the PVOH is also to be usedas a fluid loss additive, the particle size of the PVOH particles ischosen based primarily on the desired fluid loss properties (e.g. spurtand wall building coefficient). Typical particle sizes for beads orpowders range from submicron, for example about 0.2 microns, to about200 microns, for example from about 10 to about 50 microns, but theactual size depends especially upon the formation properties and onother factors known to those of ordinary skill in the art. Amorphous orpartially crystalline PVOH fibers in these size ranges are alsosuitable.

If the PVOH is to be used also as a breaker, the particles can be of abroad size range, for example from nanoparticles (for breaking a VESwithin a matrix) to the size of proppants for breaking carrier fluid.The PVOH and its properties, such as molecular weight and crystallinity,are chosen based primarily on the desired rates of dissolution in thecarrier fluid to be used at the temperature and salinity at which itwill be used. These choices can also be influenced by the desired timebefore the delayed break, which could depend upon the size of the job,whether the job is hydraulic fracturing or gravel packing, and otherfactors known to those of ordinary skill in the art, including theconcentrations and natures of the VES or crosslinked polymer and anyother additives, and the temperature.

Moreover, there can be changes to the parameters during a treatmentwhich are taken into account in the choice of a particular PVOH solid,including its chemistry and crystallinity, its size and shape, and itsconcentration, among other factors, depending upon the way it will beused as a extrametrical material or otherwise. All of these parameterscan be affected by the nature of the job, for example, whether or notfluid loss control is needed, the temperature, the nature of theformation, and the time desired before a break occurs and/or the timedesired by which a break has occurred. For example, fluid loss controlmay not be needed when gravel packing in a low permeability formationand the choices can be made on the basis of breaking properties.Suitable choices can be made with the aid of simple experiments likethose described above, or in the examples below, optionally with the aidof simulation software.

When PVOH fibers, for example, are employed they can have atemperature-triggered solubility in water, for example, above 90° C. Thetrigger temperature should be above the injection temperature, but belowthe formation temperature. In this manner the PVOH fibers are injectedwith the treatment fluid as a solid, but become solubilized downhole,after spacing the proppant islands apart for fracture closure, as thetemperature increases above the trigger temperature. Solubilization canbe delayed by employing PVOH fibers with a trigger temperature justbelow the formation temperature and/or continued injection of lowtemperature fluids to maintain the fibers below the trigger temperatureuntil dissolution is desired. Where the solubility of the fibers iscontrolled by maintaining a sub-trigger temperature, aqueous fluids withlow salinity can be employed. Also, the solubilization of the fibers canbe controlled or delayed further by using high-salinity fluid so that ifthe trigger temperature is exceeded, solubilization does not occur untilthe salinity is reduced. Care should be taken to avoid impairing fluidflow (when fluid flow is a requirement) at a condition where the fibersare not entirely soluble but have become “sticky” so as to clump andblock interstitial spaces.

The PVOH fibers can also be used in a proppant stage employing fiberassisted transport to improve proppant and other particle transportwhile reducing the amount of other fluid viscosifiers required. The atleast partially crystalline PVOH fibers can be made to dissolve afterthe treatment so that no permanent fiber residue is left in the wellboreor fracture. PVOH fibers having temperature triggers at pre-selectedtemperatures are available commercially under the trade designationKURALON K-II (Kuraray America, Incorporated), for example. These PVOHfibers completely dissolve in water when brought to a defined triggertemperature, but are virtually insoluble at lower temperature for abroad range of pH and chemical conditions. These PVOH fibers are made tohave defined temperature trigger points for aqueous dissolution atdesired temperatures between 20° C. and 90° C., in 10° C. increments.When the PVOH fiber does dissolve into an aqueous treatment or reservoirfluid, it releases polyvinyl alcohol in solution. This can effectivelybreak VES fluids. The dissolved fiber can also break some crosslinkedguar based or other polymer-viscosified fluids since the addition ofdissolved polyvinyl alcohol effectively acts to take borate, titanate,zirconate and similar ions away from the guar based molecules, therebyreducing the viscosity of the crosslinked polymer to that of the lineargel.

Fibers and other particle forms of PVOH are also available innon-crystalline or semicrystalline/amorphous form. When an amorphousPVOH is employed, dissolution of the PVOH can be controlled by salinityalone. The well treatment fluid in which the PVOH particles areintroduced should have a high salinity to avoid premature dissolution.When it is desired to dissolve the PVOH solids, salinity conditions arereduced by introducing a subsequent treatment fluid of low salinity,e.g. fresh water or 2% KCl, or where the formation water has a lowsalinity, allowing the connate water to flow to the environment of thePVOH solids.

The PVOH solids can optionally be coated to slow the dissolution.Suitable coatings include polycaprolate (a copolymer of glycolide andepsilon-caprolactone), and calcium stearate, both of which arehydrophobic. Polycaprolate itself slowly hydrolyzes. Generating ahydrophobic layer on the surface of the PVOH solids by any means delaysthe dissolution. Note that coating here can refer to encapsulation orsimply to changing the surface by chemical reaction or by forming oradding a thin film of another material. Another suitable method ofdelaying the dissolution of the PVOH solids is to suspend the solid,optionally with a hydrophobic coating, in oil or in the oil phase of anemulsion. The dissolution does not occur until low salinity watercontacts the solid PVOH above any solubility trigger temperature.

In another embodiment of the disclosure, the application relates to asubterranean formation penetrated by a wellbore and a fracture withinthe formation. Within the fracture (i.e. spaces formed between formationfaces) is a plurality of proppant clusters spaced apart by a pluralityof extrametrical material clusters. The plurality of extrametricalmaterial clusters is removable, by any suitable technique, to form openchannels around the plurality of proppant clusters to enable fluid flowfrom the formation through the fracture toward the wellbore.

In yet another aspect, method embodiments include injecting a pluralityof stages of a well treatment fluid through a wellbore into a fracturein a subterranean formation, the stages of the fluid containing at leastone of a proppant and an extrametrical material. The channelantcomprises at least one of a solid acid-precursor to generate acid in thefracture, and a solid base-precursor to generate a base in the fracture(in either case, a suitable acid or base is a material which alters thepH of an aqueous median, in either a decreasing or increasing direction,respectively). The proppant is placed in the fracture in a plurality ofproppant clusters to form pillars. The channelant then dissolves in thefracture, which may further enable fluid flow from the formation throughthe fracture toward the wellbore (the term ‘dissolve’ in the presentapplication means any suitable process, either chemical or mechanical,by which the extrametrical material voids the fracture space occupied).

Some embodiments may benefit from the presence of degradable, highenergy materials in fiber or emulsion form. Degradable, high energy(explosive or deflagrable) polymer or organic compound may be deliveredto the fracture in fiber or emulsion form and initiated to degradeoptionally with an explosion, thus leaving the proppant pack clear offiber. Further, the formation is additionally stimulated. Methane drygas wells may benefit from such embodiments because of their lowpermeability (in the range of 10 nD to 5 mD) and their longer fiberdegradation time requirements due to lower water or oil flow rates. Insome embodiments, the material contains both reducer and oxidizer in thesame molecule and does not need active media participation indecomposition. Polymers or low molecular weight products or mixturesthereof may be used. Oxidizing groups within a molecule include nitro,azido, and/or peroxide groups. Materials for fibers includenitrocellulose, nitrostarch, nitro polyvinyl alcohol, nitropolystyrene,nitroindene, nitroethylene, nitro polyurethane, dinitropropyl acrylate,polyvinyl azide, glycidyl azide polymer, and their derivatives andmixtures thereof. Materials for emulsions include nitrocellulose at adifferent content of nitro groups, nitro polyvinyl alcohol,nitropolystyrene, nitroindene nitroethylene, nitro polyurethane,dinitropropyl acrylate, polyvinyl azide, glycidyl azide polymer,2,4,6-trinitrotoluene and other nitrobenzene derivative,hexanitrostilbene, and derivatives and mixtures thereof.

High energy containing material processes may benefit from compoundsthat have both hydrocarbon fragment as a reducer and nitro (or othernitrogen-loaded) fragment as an oxidizer and initiation causedecomposition (no chemical triggers required) ideally with CO2, N2, andH₂O as final products. Fast degradable compounds may be used as solidgas precursor which provides slow or fast gas ceasing. This results indecreased hydrostatic pressure and improved production. As a practicalmatter, explosive and deflagrable fiber may be safely delivered to thelocation in wet or slurry form in water or gel. Three exemplary ways maybe selected for this degradation.

-   1. Thermal slow decomposition of the material in bulk, with no    decomposition wave propagation. The high temperatures in downhole    conditions may be used to drive this decomposition. An advantage of    this is the quick fiber disappearance and gas release. Decomposition    may take about 10 days at 100° C., and the activation energy may be    about 27 Kcal/mol.-   2. Fast deflagration with wave propagation below the speed of sound.    The fast deflagration may start after thermal or some other type of    initiation. An advantage is faster fiber degradation, product gas    release, heating up of the formation near the fracture, and control    of the triggering process.-   3. Explosion. Explosion may start after thermal or other (chemical,    pressure, irradiation, acoustic wave, etc.) initiation. Explosion    degrades fibers and induces fracture stimulation. An advantage is    fast fiber degradation, additional formation stimulation, and    controlled triggering.

Some embodiments that rely upon high energy fibers may benefit fromusing a high energy material emulsion to encapsulate other downholechemicals such as breakers, aids, etc. Hydrophobic ingredients can beadmixed to the hydrophobic phase of emulsion that remains stable at thesurface. Thus, fast release of encapsulated reagents may be achieved.

High energy material emulsions may include 90 to 10 percent water, 90 to10 percent degradable high energy material, and optionally organicsolvent to dissolve the degradable material, emulsifier, stabilizer,solid additives, encapsulated materials, and breaker aids. In downholeconditions, the emulsion is triggered for high energy material (internalphase) precipitation from the emulsion. Triggering may happen underaction of downhole temperature, chemical destabilizing of emulsiondroplets, extended surface, solids, electric discharge, ultra sound,other method, or a combination thereof.

The foregoing disclosure and description of the embodiments isillustrative and explanatory thereof. It can be readily appreciated bythose skilled in the art that various changes in the size, shape andmaterials, as well as in the details of the illustrated construction orcombinations of the elements described herein can be made withoutdeparting from the spirit of the disclosure. None of the description inthe present application should be read as implying that any particularelement, step, or function is an essential element which must beincluded in the claim scope: THE SCOPE OF PATENTED SUBJECT MATTER ISDEFINED ONLY BY THE ALLOWED CLAIMS. Moreover, none of these claims areintended to invoke paragraph six of 35 USC §112 unless the exact words“means for” are followed by a participle. The claims as filed areintended to be as comprehensive as possible, and NO subject matter isintentionally relinquished, dedicated, or abandoned.

1. A method, comprising: injecting a first treatment fluid comprising agas and substantially free of macroscopic particles through a wellboreat a pressure sufficient to initiate a fracture in a subterraneanformation; injecting a second treatment fluid comprising proppant and anextrametrical material through the wellbore and into the fracture,wherein introducing is achieved with varied and pulsed proppantconcentrations in a pumping schedule, and forming a plurality ofproppant clusters comprising proppant and the extrametrical material inthe fracture; wherein the extrametrical material consolidates theproppant into clusters, and wherein the extrametrical material isdegradable.
 2. The method of claim 1, wherein the pumping schedule isbased on fluid and formation properties.
 3. The method of claim 1,wherein the pumping schedule is achieved by varying pumping rate duringpulses.
 4. The method of claim 1, wherein the pumping schedule is basedon fluid and formation properties and is achieved by varying pumpingrate during pulses.
 5. The method of claim 1, further comprisingdegrading the extrametrical material after proppant placement in thefracture.
 6. The method of claim 5, wherein the extrametrical materialdegradation provides fluid flow paths coupling the formation to thewellbore via the fracture.
 7. The method of claim 1, wherein theextrametrical material comprises at least one of: a solid acid-precursorto generate acid; or a solid base-precursor to generate a base.
 8. Themethod of claim 1, wherein the extrametrical material generates acid inthe fracture.
 9. The method of claim 1, wherein the method is repeatedat another fracture in the wellbore.
 10. The method of claim 1, whereinthe proppant clusters are placed in transverse or longitudinal fracturesalong a wellbore deviated at an angle relative to a vertical wellbore.11. The method of claim 1, wherein a zone contacted by the first andsecond treatment fluids in the formation comprises fine grainedsedimentary rock formed by consolidation of clay and silt sizedparticles into thin, relatively impermeable layers.
 12. The method ofclaim 1, further comprising injecting a fluid comprising extrametricalmaterials in a higher concentration than the second well treatment fluidinto the fracture.
 13. The method of claim 1, wherein the extrametricalmaterial is a channelant.
 14. The method of claim 1, wherein theextrametrical material is not a channelant during the introducing andthe forming.
 15. A method, comprising: injecting a first treatment fluidcomprising a gas and substantially free of macroscopic particles througha wellbore at a pressure sufficient to initiate a fracture in asubterranean formation; injecting a second treatment fluid comprisingproppant and an extrametrical material through the wellbore and into thefracture wherein the injecting is achieved with varied and pulsedproppant concentration in a pumping schedule; placing the proppant inthe fracture in a plurality of proppant clusters, wherein theextrametrical material reinforces the proppant clusters, and wherein theextrametrical material is a removable material.
 16. The method of claim15, further comprising degrading the extrametrical material after theplacing of the proppant.
 17. The method of claim 16, wherein thedegradation of the extrametrical material is by degraded by softening,dissolving, melting, or reacting.
 18. The method of claim 15, whereinthe extrametrical material comprises a solid acid-precursor to generateacid in the fracture.
 19. The method of claim 15, wherein theextrametrical material comprises a solid base-precursor to generate abase in the fracture.
 20. The method of claim 19, wherein theextrametrical material comprises a solid acid-precursor to generate acidin the fracture.
 21. The method of claim 15, wherein the method isrepeated at another fracture in the wellbore.
 22. The method of claim15, wherein the proppant clusters are in transverse or longitudinalfractures along a wellbore deviated at an angle relative a verticalwellbore.
 23. The method of claim 15, wherein a zone contacted by thefirst and second treatment fluids in the formation comprises finegrained sedimentary rock.
 24. The method of claim 15, further comprisinginjecting a third treatment fluid comprising extrametrical materials ina higher concentration than the second well treatment fluid into thefracture.
 25. The method of claim 15, wherein the extrametrical materialis a channelant.
 26. The method of claim 15, wherein the extrametricalmaterial separates the proppant clusters.
 27. A method, comprising:constructing a system in a subterranean formation penetrated by awellbore, comprising: injecting a first treatment fluid comprising a gasand substantially free of macroscopic particles through a wellbore at apressure sufficient to initiate a fracture in a subterranean formation;injecting a second treatment fluid comprising proppant and fiber throughthe wellbore and into the fracture, wherein the fiber is a degradablematerial; placing the proppant in the fracture in a plurality ofproppant clusters; degrading the fiber; and producing formation fluidsfrom the formation.
 28. The method of claim 27, wherein the fiberconsolidates the proppant clusters.
 29. The method of claim 27, furthercomprising injecting a fluid comprising the fiber in a higherconcentration than the second well treatment fluid into the fracture.30. The method of claim 27, wherein the fiber is a channelant.
 31. Themethod of claim 27, wherein the fiber is not a channelant during theinjecting of the second treatment fluid.
 32. The method of claim 1wherein the pumping schedule is modified during injecting due toprocessing data from surface or bottomhole gauges.
 33. A methodcomprising: injecting a first treatment fluid comprising a gas andsubstantially free of macroscopic particles through a wellbore at apressure sufficient to initiate a fracture in a subterranean formation;injecting a second treatment fluid comprising proppant and fiber throughthe wellbore and into the fracture; and forming a plurality of proppantclusters comprising proppant and fiber in the fracture; wherein thefiber consolidates the proppant into clusters, and wherein the fiber isdegradable.
 34. A method comprising: injecting a first treatment fluidcomprising a gas through a wellbore at a pressure sufficient to initiatea fracture in a subterranean formation; injecting a second treatmentfluid comprising proppant and fiber through the wellbore and into thefracture forming a plurality of proppant clusters; and wherein the fiberreinforces the proppant clusters, and wherein the fiber is a removablematerial.
 35. A method, comprising: constructing a system in asubterranean formation penetrated by a wellbore, comprising: injecting afirst treatment fluid comprising a gas and substantially free ofmacroscopic particles through a wellbore at a pressure sufficient toinitiate a fracture in a subterranean formation; injecting a secondtreatment fluid comprising proppant and fiber through the wellbore andinto the fracture, wherein the fiber is a removable material; placingthe proppant in the fracture in a plurality of proppant clusters; andproducing formation fluids from the formation.